Executive Summary This report aims at examining theeconomics of three depletion drive mechanisms for the development of anoilfield: natural gas-gap depletion, natural water drive and water injection.Excel spread-sheets that integrate production controlling parameters, ex.
STOIIP, are used to obtain production data including first oil production, flowrates, and point of termination of production. This data is then utilized toperform the economic analysis and establish costs and barrel ownership. Theeconomic analysis entails CAPEX, OPEX, annual cash flow, cumulative cash flow,and revenue distribution calculations. Thus, a comparison between the threedevelopment plans is constructed and a proposition as to which is the mosteconomically viable is made. Using the ‘Technical Input” table of the excel sheet adevelopment plan was made by choosing a set number of wells in specific yearswith regards to the determined production well potential of 10 mbopd. Based on the generated production data,facility capacities’ sizes were adjusted and the well and facilities costs wereestimated. Using the cumulative cash flow, the Net Present Value versus thediscount rates were plotted to obtain the Internal Rates of Return. The three depletionstrategies yield 10%, 20%, and 40% recovery factors for the gas-cap depletion,natural water drive, and water injection respectively.
The gas-cap depletionmechanism has the lowest cumulative CAPEX, cumulative cash flow rate at 10% discountrate, and IRR of 18.46% with 119.9mmstb recoverable oil. At 10% discount rate,abandonment is initiated in year 16, after only 13 years of production.
Naturalwater drive has an IRR of 33.71% with a recovery of 240mmstb. At 10% discountrate, the field produces for 19 years before abandonment with a cumulative cashflow rate of $1108.5million.
The cumulative CAPEX of $1725million is an orderof magnitude higher than the gas-cap depletion, but remains significantly lowerthan the $3300million capex of the water injection. However, water injectionhas a cumulative oil production of 480mmstb. At 10% discount rate the IRR is19.045% and the field can produce for 21 years with a cumulative cash flow rateof $1311.9million, almost just 16% higher than the natural water drive atalmost double the expenditures making the natural water drive a betterrecommendation for the core development plan.
Field Plan, Production Profile, and Reservoir Delivery The main prospect for every production planis maximizing revenue at the lowest cost. The three plans are considered forthe IRR and NPV at 10% discount rate. The optimum value of NPV and IRR isachieved by minimizing the costs of wells and facilities while maintainingmaximum recovery. Natural Gas-CapDepletion This mechanism isdriven by the expansion of and frontal displacement of the pre-existing gas capand/or the upward migration of gas from unsaturated oil via counterflow1to mitigate the pressure decline during production. Consequently, the high gasproduction of 147mmscfd in comparison to the other two mechanisms had to beaccounted for by increasing the gas facilities and thus the capex. Figure 3illustrates the drilling plan over 13 years designed to minimize gas productionrate and facilities capex while considering well recovery potential. Initially4 wells were drilled in the second year, then 2 in the fourth, and one in years6,10,11,12, and 13.
Between years 5 and 13, drilling was kept minimal in anattempt to control the gas production rate, the rate exceeded the oilproduction rate in year 5. The oil, gas, liquid, water injection and powercapacities chosen were 50mbopd, 150mmscfd, 75mbopd, 0mbwipd, and 225 mblpd/mmscfincluding 60mbopd pipeline totaling at $1070million for capital expenditures. Thefield achieved the recovery factor of 10%, i.e. 120mmstb. Production peaked inyear 4 at 50 mstb/d (figure 4), one year after first oil production, anddecreased from 50 mstb/d to 0.
1 mstb/d in years 24 to 25. Natural Water Drive The main controllerin this mechanism is the aquifer. Similarly to the gas-cap depletion, waterinflux acts to mitigate the pressure decline driving the oil to the producingwells. The degree to which water influx affects recovery depends on the degreeof communication between the aquifer and reservoir and the amount of water thatencroaches into the reservoir.
For NWD, the drilling plan was covered in thefirst 10 years (figure 7). The production profile (figure 8) indicated peakproduction of 75 mstb/d in year 4, one year after initiation of production. Agradual decrease was observed until a rate of 11.5 mstb/d in year 22 followed by termination ofproduction in year 23. Maximum gas rate production was kept at 58mmscfd. Watercut occurs in the second year of production, and increases to 47.
5% in year 22.Consequently, oil and liquid facilities’ capacities are increased. The oil,gas, liquid, water injection and power capacities chosen were 75mbopd, 60mmscfd,100mbopd, 0mbwipd, and 160 mblpd/mmscf including 80mbopd pipeline totaling at$875million for capex.
Water Injection Water injection isthe use of waterflooding2to generate and/or increase production from oil reservoirs. The restriction of thedrilling performance to 4 wells per year caused drilling to commence as soon aspossible with 4 wells consistently drilled for the entire 11 years of drilling summingto 46 wells yielding a 40% recovery factor (figure 11). The production forecast(figure 12) conveyed a low oil production rate in comparison to that of waterand gas, consequently leading to an enormous increase in facilities capacitiesin addition to water injection facilities (figure 9) totaling at $2630millionfor capex, inclusive of 46 wells. The oil, gas, liquid, water injection and powercapacities chosen were 125mbopd, 45mmscfd, 450mbopd, 460mbwipd, and 955mblpd/mmscf including 130mbopd pipeline. Production peaked in year 4 at 121.7mmstb/d and decreased at a relatively slower rate than the other two plans reaching22.
1 mmstb/d in year 24 at which production terminated. Economic Analysis of the Three Development ScenariosNatural Gas-CapDepletion Figure 13 displaysthe value of the company across different discount rates. The NPV(10) (figure 14)is $357.7million, while the ultimate cash surplus NPV(0) is $1117million. Figure13 shows that the maximum exposure for the project is $1380million without adiscount factor and $1186million at 10% discount rate at which the depletionplan can deliver $390million if abandoned in year 16.
Additionally, theinternal rate of return (figure 15) is 18.5%. Its annual cash flow profile at10% discount rate (figure 16) indicates that production revenue initiates inyear 2, the pay-as-you-go point occurs between years 2 and 3, and the pay-outoccurs between years 6 and 7. At no discount factor the pay-out occurs almost ayear earlier. As for the profit, the company makes a total of $3929.
7million ofin-taxable income which 18% is profit (figure 17-18). Natural Water Drive For NWD, thediscounted cumulative cash flow profile (figure 19) indicates the NPV(10) is$1108.5million, with an ultimate cash surplus, NPV(0), of $2788million and anIRR of 33.7% (figure 20) making this the most robust depletion plan out of thethree. The maximum exposure for the project is $893million at 10% discount rateand $1035million without a discount factor. The annual cash flow profile (figure 21) at 10% discount rate indicatesthat production revenue starts in year 2, the pay-as-you-go point occursbetween years 2 and 3, and the pay-out occurs between years 4 and 5.
At nodiscount factor the pay-out occurs in the same year. The plan can deliver about $1137.8million at10% discount rate if abandoned in 22.
As for the profit generated with NWD, thecompany makes $8789.7million in-taxable income of which 21% is profit (figure 22-23). Water Injection For WI, figure 24 shows an NPV(10) of $1131.8millionwith an ultimate cash surplus, NPV(0), of $5249 million. The field can deliver$1333million if abandoned in year 24. This plan generates $15,657.8millionin-taxable income of which 19% is profit (figure 25-26).
However, the plan has an IRR of only 19%(figure 27). The annual cash flow profile (figure 28) shows that productionrevenue starts in year 2, the pay-as-you-go point occurs between years 2 and 3,and the pay-out point is between years 7 and 8. At no discount factor thepay-out occurs almost 2 years earlier. The maximum exposure for the projectoccurs in year 2. Reservoirand Development Sensitivities It is important toconsider economic sensitivities, both those relating to the reservoir’stechnical properties such as STOIIP and those related to development andexternal factors for example oil price. To demonstrate sensitivities, the NWDscenario is taken as a case study. Sensitivityto STOIIP and RF Figure 29 shows theeffect of having a variance in the expected STOIIP by 10% higher and lower onthe discounted cumulative cash flow with respect to the discount rates. While figure30 displays fluctuations in the recovery factor by 5% higher and lower.
Thereis a direct relation between both sensitivity variables and the NPV(10) and theIRR. As the STOIIP increases, the NPV(10) increases, however the IRR onlyincreases by about 1%. On the other hand, as the RF increases, the NPV(10) andIRR both slightly increase.
A decrease in the RF has a bigger impact, as theIRR decreases from 33.7% to 27.5%. Additionally, an increase in both factors,can cause an increase in the facilities capacities. Sensitivity to Oil Price Figure 31shows fluctuations in the oil price by $5 more and less. Similar to the RF, aslight increase in the price causes the NPV(10) to increase and the IRR toincrease from 33.7% to 38%. However, when the price decreases by the sameamount, the impact is higher, reducing the IRR from 33.
7% to 24.5%. Sensitivity to Construction Time Figure 32shows the impact of having delays in the construction period by 1 and 2 years.At no discount rate, a 2 year delay to the initial 36 months constructionperiod has a higher net present value.
This is due to the deducted operationalcosts. However, at higher discount values (10%), a two year delay decreases theNPV(10) and causes a 17% decrease in the IRR. Sensitivity to Drilling Costs Figure 33displays the impact of increasing and decreasing the drilling costs slightly by$2million. This change can be due to changeable prices of drilling muds,casings, and cements. As the well capex increases, the NPV(10) and IRR bothdecrease. The extent of changes to the NPV(10)and IRR, are visually summarized in figures 34 and 35 respectively.
DevelopmentRisks, Mitigations, and Contingency Risks in developmentplans can be due to reservoir and non-reservoir factors. These can cause higheconomical loss and decrease in value. ExplorationRisks For this field noappraisal well was drilled.
Data acquired are from a short duration PVT test.Consequently, uncertainties in pertrophysical and geological data can yieldinaccurate production forecasts. Estimations of STOIIP, contact points (gas-oiland oil-water contacts), and sizes, locations, and conditions of faults (openand close) will either be unknown or have lower accuracies. The strength of theunderlying aquifer, which is a controlling variable for the NWD plan isunknown. The aquifer is thought to be large in size with a small overlyinggas-cap. The most accurate method toacquire accurate date is to commence production and obtain production data whilechoosing the safest depletion plan. In this study, that is recommended to bethe NWD.
If the aquifer proves to be insufficient in size or strength,introducing some injectors as a secondary plan is a helpful option. Furthermore,there is no archive for drilling data in the country this being a first-oildiscovery. Higher safety margins should be introduced in drilling planning andpressure gradients calculations, as risks are higher. PoliticalRisks This being thefirst-oil in this country, there is unfamiliarity between the oil industry andthe government. Though, hopeful for revenue, the fiscal terms seem to beimproved. If a relation of mutual gainbetween both the company and the government is established through a detailedinclusive contract this can prevent any futuristic conflicts from occurring.
Additionally, awareness amongst locals, including advertisement and local talksummits for instance, can contribute to creating a positive outlook on thedevelopment plan to avoid political backlash. Finally, the political stabilityof the country must be assessed and considered as in a case of a civil war, thecompany loses money and will be inable to recover any capital or operationalexpenditures. OperationalContingencies Operationalcontingencies are critical to consider and have systems of prevention installedfor them.
These include blowouts during drilling and/or facilities damagethroughout production. RecommendedDevelopment With regards toprevious sections, the recommended development plan is the NWD. It has thehighest rate of return 33.
7% (figure 36). It has a significantly higher NPV(10)than the ND and is only 16% lower than the WI, with almost half of thedevelopment expenditures. The most critical risk for this development howeveris the strength of the aquifer.1 “The simultaneous downward movement ofoil to balance the upward flow of gas. This diametric flow pattern is referredto as counterflow.” (PetroWiki, 2014)2 The use of water injection; it is “accomplished by “voidagereplacement”—injection of water displaces oil from the pore spaces, butthe efficiency of such displacement depends on many factors (e.g., oilviscosity and rock characteristics).” (PetroWiki, 2014)